Pitfalls of Surface Well Test Analysis - Guidelines
- Bilal Hakim (ODSI) | Chris Fair (ODSI)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 23-26 April, San Jose, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- bottomhole pressure, Pressure Transient, reservoir characterization, Well test, buildup drawdown
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- 188 since 2007
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Pressure Transient Analysis (PTA) provides valuable information about the subsurface completion and reservoir. Permanent downhole pressure gauges (PDHG) are not always available in wells. In such cases, wellhead pressure (WHPG) gauges, or temporary downhole gauges (DHG) can be used to perform reservoir/completion diagnostics. Although in some cases it is safe to use raw WHP data for analysis, in a lot of cases it should not be done. Fair et al. (2002) presented a methodology to categorize wells that could be tested from the surface (well head) along with a methodology that allows surface-to-bottomhole pressure (BHP) conversion.
A few authors in the past have emphasized the importance of converting wellhead pressure and downhole gauge pressure data to mid-completion bottomhole conditions to account for friction and changing fluid density during a test. Performing PTA without correcting the gauge data for these wellbore effects can lead to inaccurate results: especially the over-estimation of skin and permeability, and underestimation of P*, and in-place hydrocarbon volumes, due to reservoir signal suppression. The WHP data could also be non-analyzable (using conventional methods) if the effects are severe. Hakim et al. (2016) further discussed the importance of this conversion and presented examples where WHP to BHP conversions in various types of wells could be performed with high accuracy using a coupled PVT-thermal wellbore model.
This paper will introduce the concept of rate of change in wellbore fluid density (wellbore signal) relative to the rate of reservoir pressure increase/decrease (reservoir signal) during a test. The purpose is to identify the factors affecting the "reservoir signal" in the measured wellhead pressure and rate data during a well flowback and during the commercial production period, and to provide guidelines to help the petroleum engineer determine the severity of these factors in a given well/reservoir system. This should help the petroleum engineer in deciding whether to rely on the WHP data or run a DHG to observe the reservoir signal.
A 3-step methodology to determine the magnitude of the wellbore signal relative to the reservoir signal will be presented with solved examples of an oil well and a gas-condensate well.
|File Size||1 MB||Number of Pages||16|
Fair, C., Cook, B., Brighton, T., Redman M., & Newman S. (2002, January 1). Gas/Condensate and Oil Well Testing - From the Surface. Society of Petroleum Engineers. doi:10.2118/77701-MS
Hakim, B. A., Fair, C., & Montague, E. (2016, October 25). The Effect of Wellbore Temperature Changes and Frictional Losses on Well Test Interpretation Results. Society of Petroleum Engineers. doi:10.2118/182329-MS
Fraga, E. 2009. Heat Transfer and Pipe Flow. Homepages. ucl, http://www.homepages.ucl.ac.uk/~ucecesf/tmp/heatandpipes.pdf (accessed 20 July 2016)